1.  What happened on June 15

Energy Minister Adrian Dix announced that the province is “seriously” re-examining two large hydroelectric projects: Site E on the Peace River and a project on the Homathko River near Bute Inlet.¹ Both projects are currently prohibited under the Clean Energy Act.² Dix said legislative changes would be introduced in the fall 2026 session—not to remove the prohibitions outright, but to allow technical review of whether the projects are viable.“It’s firm power that backs up intermittent resources, such as wind and solar,” Dix said. “To get that capacity, we have to open all potential sources of generation, including new hydroelectric projects.”³Site E would sit at the confluence of the Peace and Alces rivers near the Alberta border, generating up to 750 megawatts. The Homathko project, located in Homalco First Nation territory, would generate roughly 900 megawatts. For comparison, the recently completed Site C (now the John Horgan Dam) generates approximately 1,200 megawatts.

BC Hydro CEO Charlotte Mitha framed the context: “Demand for electricity is rising faster than in the past few decades. It’s driven by population growth, electrification, and new industrial development.”⁴ The utility projects a 20% increase in demand by 2030 and a 50% increase by 2050, with peak demand rising 40%.⁵

2. The Peace River inventory

The Peace River dam sites were first identified in a 1958 hydroelectric inventory. Five sites were catalogued, lettered A through E. Site A became the W.A.C. Bennett Dam (2,730 MW), completed in 1968. Site B became the Peace Canyon Dam (694 MW), completed in 1980. Site C became the John Horgan Dam (1,100 MW), completed in 2025. Site D, between the Bennett and Peace Canyon dams, was never developed. Site E, at the downstream end of the Peace near the Alberta border, was shelved and then prohibited by statute.The 2010 Clean Energy Act explicitly barred construction at Site E and on the Homathko River. At the time, the rationale was that Site C alone would meet the province’s foreseeable needs. That assumption was wrong.

3. Site C: The cost of the precedent

Site C’s final cost was $16 billion—more than double the $6.6 billion estimated in the 2007 feasibility study and nearly double the $8.3 billion approved in 2014.⁶ The dam took a decade to build. First power flowed in October 2024; all six generating units were operational by August 2025.A 224-page lessons-learned report filed with the BC Utilities Commission in October 2025 identified three systemic failures: understaffing of BC Hydro’s project management team, inadequate risk budgeting, and insufficient independent oversight.⁷ Major cost drivers included $1.1 billion in right-bank foundation remediation, $600 million for left-bank crack repairs, and $1.6 billion in COVID-related delays.The 143% cost escalation is the central fact of any big-hydro conversation in British Columbia. Site C’s implied capital cost per installed kilowatt—roughly $14,500/kW—is among the highest for any hydroelectric project in the developed world. Applied to Site E’s 750 MW, the same cost structure would imply a project in the range of $10–11 billion. Applied to Homathko’s 900 MW, the figure exceeds $13 billion.The question is not whether Site C’s cost overruns were anomalous. The question is whether any government can credibly commit to building a comparable project and controlling its costs.

Where Resource Works stood

Site C was controversial from the start. When the project came before the BC Utilities Commission in 2017, much of the opposition came from self-described clean energy advocates who argued the power was not needed. Environmental groups, some First Nations, and the provincial NDP (then in opposition) campaigned against it. The project became a political liability, and in 2017 the new NDP government referred it to the BCUC for review before ultimately deciding to proceed on the grounds that cancellation would cost more than completion.Resource Works supported Site C throughout. The position was not popular in every quarter, but it was consistent: B.C. would need substantially more clean electricity to power industrial development, critical minerals extraction, LNG export, population growth, and the electrification of transportation and heating. The arithmetic seemed obvious to us. The demand was coming. The only question was whether the province would have the generating capacity to meet it.That is what came to pass. Resource Works stood with the communities, the workers, and the advocates for a strong and responsible resource economy who understood that building large infrastructure is difficult, expensive, and necessary. Site C is now the John Horgan Dam, all six turbines are running, and BC Hydro is projecting the kind of demand growth that vindicates the decision to build. The lesson is not that the project was managed well. The lesson is that the underlying case for more firm, clean generation was correct then and is more urgent now.

4. Homalco and the Homathko

The Homathko River project has a longer history than its current incarnation suggests. In the mid-2000s, Plutonic Power (later acquired by Alterra) proposed a massive run-of-river complex in the Bute Inlet watershed: 17 facilities on tributaries of the Homathko, Southgate, and Orford rivers, with a combined capacity of approximately 1,100 MW.⁸ The proposal drew opposition from environmental groups and some First Nations, and was ultimately blocked by the Clean Energy Act.The Homalco First Nation’s territory encompasses the Bute Inlet area. Their position on hydroelectric development has evolved from cautious engagement with the original Plutonic Power proposal to a more assertive role as proponents. The current proposal positions Homalco as the primary First Nations partner in any Homathko development—a significant shift from the previous model, in which a private developer held the lead and First Nations were consulted rather than centred.This matters under DRIPA. The Declaration on the Rights of Indigenous Peoples Act requires that government decision-making align with the UN Declaration, including the standard of free, prior, and informed consent. The 2024 Gitxaala decision confirmed that DRIPA has immediate legal force—it is not aspirational.⁹ A Homalco-led Homathko project would satisfy the consent requirement from the outset. An externally imposed project would face a legal barrier that may be insurmountable.

5. The gas reality

While the province debates whether to spend a decade and tens of billions on new dams, the market is already answering the firm-power question with natural gas. In June 2026, BC Hydro applied to the BC Utilities Commission to extend contracts for two gas plants it had planned to shut down: Capital Power’s 275 MW Island Generation facility in Campbell River and the 120 MW McMahon cogeneration plant in Taylor.¹⁰As Barry Penner noted, the province’s CleanBC policies “appear to have crashed headlong into economic reality, as many have predicted.” Nelson Bennett, writing in Resource Works, went further: “I’m going to go out on a limb here and predict that the next new dispatchable power plant built in B.C. will be fired by natural gas.”¹¹BC Hydro CEO Charlotte Mitha, speaking to the Greater Vancouver Board of Trade, conceded the point in careful language: “Peaking plants that provide five days of support a year—very low GHG emissions—are needed in a lot of jurisdictions. I fully support the concept of gas peaking plants that need to fill in the 10 days a year for the peak loads on the system.”The cost comparison is stark. Site C cost $16 billion for 1,100 MW. The Shepard Energy Centre in Calgary—an 800 MW combined-cycle gas plant—was completed in 2015 for approximately $1.5 billion.¹² That is roughly ten times cheaper per megawatt. A gas plant can be built in three to five years. A dam takes a decade or more.

The CleanBC collision

The 2019 CleanBC framework was built on the assumption that electrifying everything—homes, vehicles, industry—would be powered by existing hydro capacity plus modest additions of renewables. That assumption required demand growth to be orderly and manageable. It was neither. LNG export terminals, data centres, mining electrification, and population growth have produced demand projections that CleanBC never contemplated.The four new wind farms recently approved by the province illustrate the gap. Their combined nameplate capacity is 1,158 MW—equivalent to Site C. But wind’s capacity factor in B.C. is 30 to 40%. Actual delivered power: 350 to 460 MW. And none of it is available on a windless January night when the system peaks at 11,300 MW, as it did during the cold snap in early 2024.The Iberian Peninsula blackout of April 2025 demonstrated what happens when a grid leans too heavily on intermittent sources. At the moment of collapse, 71% of generation on the Spanish and Portuguese grid was intermittent—59% solar, 12% wind—and only 16% was firm.¹³ Mitha cited the event directly when explaining BC Hydro’s need for firm dispatchable power.

The rest of the world has moved on

The Mark Carney government’s National Electricity Strategy, released May 14, 2026, states plainly: “Realising these savings will require a willingness to use a wide range of energy, including natural gas.”¹⁴ The federal position is now that natural gas is part of Canada’s electricity future. B.C. remains the holdout—a province with one of the world’s largest natural gas reserves, using legislation drafted in 2010 to prohibit the most cost-effective firm generation technology available to it.The question is not whether gas-fired generation will play a role in B.C.’s electricity system. BC Hydro’s own actions confirm that it already does. The question is whether the province will plan for gas capacity honestly, or continue to treat it as a regrettable concession made in whispers while publicly promising an all-electric future that the grid cannot deliver.

6.  The electricity gap

BC Hydro’s demand projections are not speculative. They reflect commitments already made. Ksi Lisims LNG alone requires approximately 600 MW—nearly as much as a new Site E would produce.¹⁵ Two recent calls for power have contracted wind and solar projects sufficient for 850,000 homes, but most of that capacity will serve industrial users, and none of it is firm.The province’s response to date has three planks: conservation (Power Smart 2.0, targeting 800 MW of capacity savings and 2,200 GWh of annual energy savings by 2030¹⁶), optimisation of existing infrastructure (including upgrades to the Revelstoke Dam), and new generation.¹⁷ The first two planks are necessary but insufficient. The third plank is where the debate begins.

What the alternatives deliver

The table exposes the core dilemma. Wind and solar are fast and cheap but not firm. Hydro upgrades are the best value but limited in scale. Natural gas is firm, fast, and scalable but politically constrained by the province’s climate commitments. Large hydro is firm and scalable but slow, expensive, and carries execution risk that Site C has made impossible to dismiss. SMRs are not on the horizon in B.C. Battery storage supplements but does not replace firm generation.

7. Is big hydro a fever dream?

No. But it is no longer the default answer, and it carries risks that the province has not yet demonstrated it can manage. The case for Site E and Homathko rests on three premises. First, B.C. needs firm power, and no combination of wind, solar, and batteries can deliver it at scale. Second, large hydro is the only zero-emission firm generation technology that B.C. has built before. Third, the alternative—natural gas—is politically difficult for a government that has staked its credibility on clean energy.The case against is equally direct. Site C cost $16 billion and took a decade. The same government that declared Site C “should never have been started” is now proposing to do it again, twice. Gas-fired generation can be built at a tenth of the cost in a third of the time. BC Hydro is already extending gas plant contracts it had planned to cancel. The federal government has acknowledged that natural gas is part of Canada’s electricity future. The rest of the world—including jurisdictions with far more ambitious climate targets than B.C.—continues to build gas capacity without apology.And the cost of delay is compounding. Every year that B.C. debates firm power is a year that mines, LNG terminals, and data centres either wait or leave.

What Resource Works concludes

The province’s electricity gap is real, growing, and urgent. Big hydro is a credible part of the long-term answer, but only if three conditions are met:

• Cost discipline. An independent cost authority with binding oversight must be established before construction begins. The Site C lessons-learned report identified the failures; repeating them is a choice.
• Indigenous partnership. The Homathko project should proceed only as an Indigenous-led venture with Homalco at the centre. This is both a legal requirement under DRIPA and the model most likely to secure social licence.
• Gas in the plan, not in the footnotes. The 2019 CleanBC framework assumed a world that no longer exists. BC Hydro’s own actions—extending gas contracts, admitting peak demand cannot be met without gas peakers—confirm that natural gas generation is not a temporary embarrassment but a structural necessity. The province should say so plainly and plan accordingly, as Ottawa now does. The alternative is a grid that looks increasingly like the one that failed in Spain and Portugal: heavy on aspiration, light on firm power, and vulnerable when the weather turns.

Big hydro is not a fever dream. But treating it as the only acceptable answer—while quietly relying on the gas plants you promised to close—is.

1. Mark Page, “B.C. looking at revisiting Site E and Homathko dams,” Campbell River Mirror, June 15, 2026. ↩︎
2. Clean Energy Act, S.B.C. 2010, c. 22. Prohibits construction of Site E and projects on the Homathko River. ↩︎
3. Adrian Dix, Energy Minister, announcement June 15, 2026. Quoted in CBC News and Canadian Press reports. ↩︎
4. BC Hydro CEO Charlotte Mitha, quoted June 15, 2026: “Demand for electricity is rising faster than in the past few decades.” ↩︎
5. BC Hydro, Long-Term Energy Plan submission, 2025. Demand projections: 20% increase by 2030, 50% by 2050. ↩︎
6. Site C final cost: $16 billion (2021 revised estimate). Original 2014 approval: $8.3 billion. 2007 feasibility: $6.6 billion. ↩︎
7. BC Hydro, Site C lessons learned report, filed with BCUC October 30, 2025. 224 pages. ↩︎
8. Knight Piesold, “1,100 MW Bute Inlet Hydroelectric Project,” project reference. Original Plutonic Power / General Electric proposal. ↩︎
9. Declaration on the Rights of Indigenous Peoples Act, S.B.C. 2019, c. 44. Gitxaala Nation v. British Columbia (2024) confirmed DRIPA has immediate legal force. ↩︎
10. BC Hydro application to BCUC to extend contracts for Island Generation (275 MW, Campbell River) and McMahon cogeneration (120 MW, Taylor). June 2026. ↩︎
11. Nelson Bennett, “Why natural gas peaker plants in B.C. are inevitable,” Resource Works, June 4, 2026. ↩︎
12. Shepard Energy Centre, Calgary: 800 MW combined-cycle natural gas plant, completed 2015, cost approximately $1.5 billion. Capital Power / ENMAX. ↩︎
13. Iberian Peninsula blackout, April 28, 2025. At the time of collapse, 71% of generation was intermittent (59% solar, 12% wind), 16% firm (nuclear and gas). ↩︎
14. Government of Canada, National Electricity Strategy, May 14, 2026: “Realising these savings will require a willingness to use a wide range of energy, including natural gas.” ↩︎
15. Ksi Lisims LNG electricity requirement: approximately 600 MW. Source: project filings and BC Hydro IRP. ↩︎
16. BC Hydro Power Smart 2.0: $1 billion investment over three years, targeting 800 MW capacity savings and 2,200 GWh annual energy savings by 2030. ↩︎
17. BC Government, “Powering Growth, Fuelling Opportunity,” June 2026. Three-pronged approach: conserve, optimise, build. ↩︎